Hydraulic fracture geometry monitoring with downhole distributed strain measurements

ABSTRACT

A system for use with a subterranean well can include a distributed strain sensor that senses strain along a casing which lines a treatment wellbore. The distributed strain sensor can extend across at least one fracture that intersects the wellbore. A method of monitoring at least one fracture in a subterranean well can include sensing strain in a portion of a casing where the fracture intersects the casing, the sensing being performed with a distributed strain sensor, and determining a geometry of the fracture, based on the sensing. The geometry can include a width of the fracture, a height of the fracture and an orientation of the fracture relative to a wellbore. The distributed strain sensor can include an optical waveguide.

TECHNICAL FIELD

This disclosure relates generally to equipment utilized and operations performed in conjunction with subterranean wells and, in one example described below, more particularly provides for hydraulic fracture geometry monitoring using downhole distributed strain measurements.

BACKGROUND

A hydraulic fracture is typically formed in an earth formation by forcing fluid under pressure into the formation, with the pressure being great enough to split or crack the formation. As the fracture is being formed, proppant (such as, sand or man-made particles) can be introduced into the fracture, so that the fracture will be held open by the proppant after the pressure is relieved.

Over time, as fluid is produced from the formation, pressure in the fracture will typically decrease, and the fracture can become narrower due to, for example, embedment of the proppant into sides of the fracture, crushing of the proppant, etc. Such narrowing of the fracture will decrease communicability of fluids between the formation and a wellbore that penetrates the formation.

It will, thus, be appreciated that improvements in the art of monitoring fracture geometry are continually needed.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a representative partially cross-sectional view of a well system and associated method which can embody principles of this disclosure.

FIG. 2 is an enlarged scale representative cross-sectional view of a casing and fracture portion of the system.

FIG. 3 is a representative schematic view of a spatial relationship between a treatment well and a fracture.

FIG. 4 is a representative graph of fracture induced axial strain in a formation versus distance along the treatment well for various different fracture pressures.

FIG. 5 is a representative schematic view of another example of a spatial relationship between a treatment well and a fracture.

FIG. 6 is a representative graph of fracture induced axial strain in the formation versus distance along the treatment well for various different fracture heights.

FIG. 7 is a representative schematic plan view of another example of a spatial relationship between a treatment well and a fracture.

FIG. 8 is a representative graph of fracture induced axial strain in the formation versus distance along the treatment well for various different fracture orientations.

FIG. 9 is a representative graph of axial strain in casing and formation versus distance along the treatment well.

FIG. 10 is a representative cross-sectional view of a fracture having a changed width.

FIG. 11 is a representative graph of production/injection versus distance along the treatment well.

DETAILED DESCRIPTION

Representatively illustrated in FIG. 1 is a system 10 for use with a subterranean well, and an associated method, which can embody principles of this disclosure. However, it should be clearly understood that the system 10 and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system 10 and method described herein and/or depicted in the drawings.

In the FIG. 1 example, a wellbore 12 penetrates an earth formation 14. It is desired to fracture the formation 14 at various zones 14 a-e, in order to increase fluid communicability between the wellbore 12 and each of the zones. The zones 14 a-e could be sections of the same formation 14, or they could be sections of multiple formations.

As depicted in FIG. 1, the wellbore 12 is lined with casing 16 and cement 18. As used herein, the term “casing” is used to indicate a protective wellbore lining. Casing can be any of the tubulars known to those skilled in the art as tubing, casing or liner. Casing can be made of metal (such as, steel) or non-metals (such as, polymer or composite materials). Casing can be segmented or continuous. Casing can be pre-formed or formed in situ. Thus, the scope of this disclosure is not limited to use of any particular type of casing.

As used herein, the term “cement” is used to indicate a hardenable substance that seals off an annular space (such as, between a casing and a wellbore, or between multiple tubulars) and secures a casing or other tubular therein. Cement is not necessarily cementitious, since epoxies, other polymers, composites, etc., can be used instead of, or in combination with, cementitious material. Thus, the scope of this disclosure is not limited to use of any particular type of cement.

In the FIG. 1 example, the casing 16 and cement 18 have been perforated in one or more clusters at the zone 14 a, the zone 14 a is then fractured (e.g., by forcing fluids at high pressure into the formation 14 via the perforations 28 a), and then a plug 22 is set in the casing to isolate the zone 14 a. The casing 16 and cement 18 are then perforated at the zone 14 b, the zone 14 b is then fractured (e.g., by forcing fluids at high pressure into the formation 14 via the perforations 28 b), and then another plug (not shown) is set in the casing to isolate the zone 14 b.

This process is repeated, until all of the zones 14 a-e have been fractured. Fractures 32 are formed in each of the zones 14 a-e.

In other examples, the zones 14 a-e may not be individually perforated, fractured and then isolated by means of plugs set in the casing 16. For example, sleeves and ports (not shown) may be connected in the casing 16 at each of the zones 14 a-e to provide for selective communication with, and isolation from, the individual zones. Thus, the scope of this disclosure is not limited to use of any particular fracturing technique or sequence of fracturing operations.

Also included in the system 10 is a distributed strain sensor 30. In this example, the strain sensor 30 is connected on an exterior of the casing 16.

The strain sensor 30 is “distributed,” in that the strain sensor can sense strain at a very large number of locations, or substantially continuously, along its length. At present, typical commercially available optical fiber distributed strain sensors have a resolution of about one meter, so that, in a one thousand meter section of interest in a wellbore, about one thousand strain sensing locations are available.

Strains sensed by the distributed strain sensor 30 can be available for evaluation in real time, so that decisions can be made very quickly (such as, while a fracturing operation is being performed) based on this strain information. As used herein, the term “real time” means that an activity is performed immediately, such as, within a few seconds or minutes, instead of hours or days after an operation is concluded.

With the strain information available in real time, for example, changes can be made to a fracturing operation while it progresses, so that desired and/or optimum results can be achieved from the fracturing operation. However, it should be understood that it is not necessary for the strain information to be available in real time in keeping with the scope of this disclosure.

In some examples, monitoring of strain can be performed for extended periods (such as, for months or years), in order to evaluate how fracture geometry changes over time (for example, as the formation is drained and formation pressure decreases). In those situations and others (for example, to perform a post-fracturing evaluation in order to determine how operations could be improved, provide fracture data to a customer, etc.), real time output of strain information may not be a high priority.

In the FIG. 1 example, the distributed strain sensor 30 extends longitudinally across the perforated sections 28 a,b of the casing 16 so that, when fractures 32 are formed, the sensor will extend across the fractures. This will enable the sensor 30 to be used to detect how, when and where the fractures 32 form. For example, the sensor 30 can be used to detect the fractures 32 formed in the zones 14 a,b, and can also be used to detect that fractures have not yet been formed in any of the zones 14 c-e. Oriented perforating (well-known to those skilled in the art) can be used to avoid damage to the strain sensor 30 while perforating.

Although the sensor 30 is representatively depicted as extending longitudinally along the casing 16, parallel to a longitudinal axis 34 of the casing, in other examples the sensor could extend in other manners (e.g., helically or in a zig-zag pattern) along the casing. In addition, although the sensor 30 extends across the perforated sections 28 a-f of the casing, the sensor preferably does not extend across any perforations themselves, either when the perforations are formed, or when fluid is injected or produced through the perforations.

Referring additionally to FIG. 2, an enlarged scale cross-sectional view of a portion of the system 10 is representatively illustrated. In this view, the manner in which a fracture 32 intersects the wellbore 12 and extends through the cement 18 to the casing 16 can be more clearly seen. No proppant is depicted in FIG. 2 for clarity of illustration, but it will be appreciated by those skilled in the art that proppant would typically be placed in the fracture 32.

In this example, the distributed strain sensor 30 is attached to an exterior of the casing 16 with straps or clamps 36. A sufficient number of the clamps 36 can be used to ensure that the sensor 30 experiences any strain in the casing 16 with a desired resolution.

The sensor 30 of FIG. 2 includes an optical waveguide 38 housed within a protective outer tube 40. A filler 42 fills an annular space between the optical waveguide 38 and the tube 40, and the filler ensures that the optical waveguide experiences the same strain as experienced by the tube.

For example, the filler 42 could comprise an epoxy or other high strength hardenable polymer adhesive. In other examples, the filler 42 could be a material that hardens relatively slowly, so that it is flexible when deployed, but is set when fracturing operations are performed. Thus, the scope of this disclosure is not limited to use of any particular filler material.

The optical waveguide 38 can be a single mode, multi-mode, polarization maintaining or other type of optical waveguide. The optical waveguide 38 may comprise fiber Bragg gratings (FBG's), intrinsic or extrinsic Fabry-Perot interferometers, or any alteration of, or perturbation to, its refractive index along its length. The optical waveguide 38 may be in the form of an optical fiber, an optical ribbon or other waveguide form. Thus, the scope of this disclosure is not limited to use of any particular type of optical waveguide.

The optical waveguide 38 is optically connected to an optical interrogator 44, for example, at or near the earth's surface. The optical interrogator 44 is depicted schematically in FIG. 1 as including an optical source 46 (such as, a laser or a light emitting diode) and an optical detector 48 (such as, an opto-electric converter or photodiode).

The optical source 46 launches light (electromagnetic energy) into the waveguide 38, and light returned to the interrogator 44 is detected by the detector 48. Note that it is not necessary for the light to be launched into a same end of the optical waveguide 38 as an end via which light is returned to the interrogator 44.

Other or different equipment (such as, an interferometer or an optical time domain or frequency domain reflectometer) may be included in the interrogator 44 in some examples. The scope of this disclosure is not limited to use of any particular type or construction of optical interrogator.

A computer 50 is used to control operation of the interrogator 44, and to record optical measurements made by the interrogator. In this example, the computer 50 includes at least a processor 52 and memory 54. The processor 52 operates the optical source 46, receives measurement data from the detector 48 and manipulates that data. The memory 54 stores instructions for operation of the processor 52, and stores processed measurement data. The processor 52 and memory 54 can perform additional or different functions in keeping with the scope of this disclosure.

In other examples, different types of computers may be used, and the computer 50 could include other equipment (such as, input and output devices, etc.). The computer 50 could be integrated with the interrogator 44 into a single instrument. Thus, the scope of this disclosure is not limited to use of any particular type or construction of computer.

The optical waveguide 38, interrogator 44 and computer 50 may comprise a distributed strain sensing (DSS) system capable of detecting strain as distributed along the optical waveguide. For example, the interrogator 44 could be used to measure Brillouin or coherent Rayleigh scattering in the optical waveguide 38 as an indication of strain energy as distributed along the waveguide.

In addition, a ratio of Stokes and anti-Stokes components of Raman scattering in the optical waveguide 38 could be monitored as an indication of temperature as distributed along the waveguide in a distributed temperature sensing (DTS) system. In other examples, Brillouin scattering may be detected as an indication of temperature as distributed along the optical waveguide 38.

In further examples, fiber Bragg gratings (not shown) could be closely spaced apart along the optical waveguide 38 (at least in locations where the fractures 32 are formed), so that strain in the waveguide will result in changes in light reflected back to the interrogator 44. An interferometer (not shown) may be used to detect such changes in the reflected light.

It will be appreciated from a careful consideration of FIG. 2 that, as the fracture 32 widens, tensile strain in the casing 16 will result at a location where the fracture meets the casing. As the fracture 32 widens, the tensile strain will increase. At locations spaced apart from the fracture 32, compressive strain will be experienced in the casing 16 due to the widening fracture. Similarly, as the fracture 32 closes, the tensile strain in the casing 16 at the location where the fracture meets the casing will decrease, and the compressive strain at locations spaced apart from the fracture will also decrease.

Referring additionally now to FIGS. 3 & 4, theoretical strain in formation rock surrounding a treatment well is provided at various pressures in the fracture 32. FIG. 3 depicts the fracture 32 dimensions and orientation relative to the treatment well longitudinal axis 34, and FIG. 4 is a graph of axial (longitudinal) strain versus distance along the treatment wellbore 12.

In FIG. 3, the example fracture 32 is oriented orthogonal to the wellbore axis 34. The fracture 32 has a height h_(f) of 300 feet (˜91.4 meters). S_(v) is vertical (overburden) stress in the formation 14, S_(hmax) is maximum horizontal stress, and S_(hmin) is minimum horizontal stress. The wellbore axis 34 in this example is aligned with a direction of the minimum horizontal stress, thereby influencing the fracture 32 to form orthogonal to the wellbore axis.

In FIG. 4, axial strain (longitudinal relative to the wellbore 12) is plotted versus distance along the wellbore relative to the location where the fracture 32 intersects the wellbore, for various net pressures (P). As indicated by FIG. 4, as pressure in the fracture 32 increases, compressive strain in the rock also increases.

Interestingly, the compressive strain increases as a distance from the fracture 32 increases, until a point of extremum 56 is reached, beyond which the compressive strain decreases asymptotically. These points of extremum 56 are related to the height h_(f) of the fracture 32. Thus, by sensing the strain, the height h_(f) of the fracture can be empirically determined.

A magnitude of the strain at a given pressure is related to a width of the fracture 32. Thus, by sensing the strain at a known pressure in the fracture 32, a width of the fracture can be determined. By sensing changes in the sensed strain over time at known pressures, changes in the fracture 32 width can be monitored.

Referring additionally now to FIGS. 5 & 6, theoretical strain in formation rock surrounding a treatment well is provided at given net pressure (P_(net)) of 1000 pounds per square inch (˜6895 kpa) in the fracture 32 for different fracture heights h_(f). FIG. 5 depicts the fracture 32 dimensions and orientation relative to the treatment well longitudinal axis 34, and FIG. 6 is a graph of axial (longitudinal) strain versus distance along the treatment wellbore 12.

In FIG. 5, L_(f) is the half-length of the fracture 32. In this example, the half-length L_(f) is 400 ft (˜122 meters). FIG. 6 demonstrates how a distance between the points of extremum 56 at a given pressure in the fracture 32 is related to the height h_(f) of the fracture.

Referring additionally now to FIGS. 7 & 8, theoretical strain in formation rock surrounding a treatment well is provided at various angular orientations of the fracture 32 relative to the wellbore axis 34. FIG. 7 depicts the angular orientation of the fracture 32 relative to the treatment well longitudinal axis 34 in plan view, and FIG. 8 is a graph of axial (longitudinal) strain versus distance along the treatment wellbore 12.

In FIG. 7, θ is the angular orientation of the fracture 32 relative to the wellbore axis 34. In FIG. 8, the manner in which the strain in the formation rock changes, depending on the angular orientation of the fracture 32 can be clearly seen.

The strain curves depicted in FIG. 8 were computed for a fracture pressure (P_(net)) of 1000 psi (˜6895 kpa), fracture half-length L_(f) of 400 ft (˜122 meters) and fracture height h_(f) of 300 ft (˜91.4 meters). Note how a shape of the strain curves change as the fracture 32 orientation changes. Thus, it will be appreciated that an orientation of the fracture 32 relative to the wellbore axis 34 can be empirically determined, based on comparing the sensed strain versus distance along the wellbore axis to the modeled strain for an assumed fracture geometry.

Referring additionally now to FIG. 9, axial strain in the formation rock and axial strain in the casing 16 is plotted versus distance along the wellbore axis 34. Note that these strain curves overlap over most of their extents. This is because the formation 14 is substantially coupled to the casing 16 over most of its length by the cement 18 (see FIG. 1).

However, where the fracture 32 splits the cement 18 (see FIG. 2), there is no direct coupling between the formation 14 and the casing 16. At this area, the casing 16 will experience tensile strain. This tensile strain can be detected using the distributed strain sensor 30, because the sensor extends across the fracture 32 and is coupled to the casing 16 (see FIG. 2).

Thus, the distributed strain sensor 30 can be used to detect not only a presence of the fracture 32, but also various geometric values of the fracture (e.g., width, height and orientation relative to the wellbore 12). Changes in the fracture 32 (such as, changes in the fracture width) over time can be determined by monitoring changes in the strain over time.

Strain events occurring during production from a well can also be related to changes in a production profile (production as distributed along a wellbore) obtained from distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) monitoring systems (production monitoring with DTS and DAS systems is well known to those skilled in the art). In this manner, it can be ascertained whether mechanical deterioration of fractures (e.g., resulting in decreased fracture width) causes changes in production behavior.

Referring additionally now to FIG. 10, the fracture 32 is representatively illustrated, the fracture having experienced a change in width (w_(f)). As with FIG. 2, no proppant is depicted in the fracture 32 for clarity of illustration.

A previous width of the fracture 32 is shown in FIG. 10 in dashed lines. The fracture width w_(f) could change for any of a variety of reasons, or a combination of reasons. For example, proppant in the fracture 32 may have been crushed, the proppant could have displaced from the fracture (such as, back into the casing 16), the proppant could have become embedded into sides of the fracture, etc. Thus, the scope of this disclosure is not limited to any particular reason for the fracture width w_(f) to change.

It will be appreciated that, if the fracture width w_(f) decreases, communicability between the formation 14 and the interior of the casing 16 via the fracture will also be decreased. As a result, production or injection of fluids via the fracture 32 can be expected to decrease accordingly.

Referring additionally now to FIG. 11, a graph of production/injection versus distance along the wellbore 12 is representatively illustrated. The vertical production/injection axis can represent any suitable indicator of production or injection, such as, mass or volumetric flow rate, flow velocity, etc. The horizontal distance axis is centered approximately at the perforations 28 a as depicted in FIG. 10.

In solid lines in FIG. 11, it can be seen that production/injection increases at the perforations 28 a, compared to either side of the perforations along the wellbore 12. This is to be expected, in this example, since there is no communicability with the formation 14, except at the perforations 28 a.

In dashed lines in FIG. 11, it can be seen that production/injection was previously greater. A reduction in the production/injection is experienced, due to the decrease in fracture width w_(f) depicted in FIG. 10.

Thus, it will be understood that changes in the fracture geometry can be correlated to changes in production/injection. For example, if the strain sensor 30 detects a change in strain indicating that the fracture width w_(f) has decreased, and concurrently a decrease in production/injection at the fracture 32 is detected, it can be deduced that the change in production/injection is due to the change in fracture width.

Note that measurements of production/injection can be obtained by any of a variety of different means. For example, distributed temperature sensing systems, distributed acoustic sensing systems, conventional production logging tools, downhole flowmeters and other equipment and techniques can be used to measure production or injection. Therefore, the scope of this disclosure is not limited to any particular production/injection measurement method or technique.

It may now be fully appreciated that the above disclosure provides significant advances to the art of monitoring fracture geometry. In examples described above, values of various geometric dimensions of the fracture 32 can be determined by measuring strain along the casing 16 with the distributed strain sensor 30.

A system 10 for use with a subterranean well is provided to the art by the above disclosure. In one example, the system 10 comprises a distributed strain sensor 30 that senses strain along a casing 16 which lines a wellbore 12. The distributed strain sensor 30 extends across at least one fracture 32 that intersects the wellbore 12.

The distributed strain sensor 30 may comprise an optical waveguide 38. The system 10 can include an optical interrogator 44 that detects optical scatter in the optical waveguide 38. In other examples, other types of distributed strain sensors may be used.

The distributed strain sensor 30 may be positioned external to the casing 16.

The fracture 32 may extend outwardly from the casing 16 into an earth formation 14 penetrated by the wellbore 12.

The distributed strain sensor 30 may extend across multiple perforated sections 28 a-f of the casing 16. Fracture initiation at each of the perforated sections 28 a-f can be indicated respectively by tensile strain in the casing 16 sensed by the distributed strain sensor 30 at each of the perforated sections 28 a-f.

Closure of the fracture 32 can be indicated by a reduction of tensile strain in the casing 16 sensed by the distributed strain sensor 30. A change in a width w_(f) of the fracture 32 can be correlated to a change in fluid flow (production/injection) between the wellbore 12 and an earth formation 14 penetrated by the wellbore 12.

A method of monitoring at least one fracture 32 in a subterranean well is also provided to the art by the above disclosure. In one example, the method comprises sensing strain in a portion of a casing 16 where the fracture 32 intersects the casing 16, the sensing being performed with a distributed strain sensor 30; and determining a geometry of the fracture 32, based on the sensing.

The geometry can comprise a selected one or more of: width of the fracture 32, height of the fracture and orientation of the fracture relative to a wellbore 12.

The method can also include performing the strain sensing step and geometry determining step over time, thereby detecting changes in the geometry of the fracture 32 over time. The method can include correlating a change in the geometry (e.g., the width w_(f)) of the fracture 32 to a change in fluid flow between a wellbore 12 and an earth formation 14 penetrated by the wellbore.

Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example's features are not mutually exclusive to another example's features. Instead, the scope of this disclosure encompasses any combination of any of the features.

Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used.

It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.

The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.”

Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents. 

What is claimed is:
 1. A system for use with a subterranean well, the system comprising: a distributed strain sensor that senses strain along a casing which lines a treatment wellbore, wherein the distributed strain sensor extends across at least one fracture that intersects the wellbore.
 2. The system of claim 1, wherein the distributed strain sensor comprises an optical waveguide.
 3. The system of claim 2, further comprising an optical interrogator that detects optical scatter in the optical waveguide.
 4. The system of claim 1, wherein the distributed strain sensor is positioned external to the casing.
 5. The system of claim 1, wherein the fracture extends outwardly from the casing into an earth formation penetrated by the wellbore.
 6. The system of claim 1, wherein the distributed strain sensor extends across multiple perforated sections of the casing, and wherein fracture initiation at each of the perforated sections is indicated respectively by the strain in the casing sensed by the distributed strain sensor at each of the perforated sections.
 7. The system of claim 1, wherein closure of the fracture is indicated by a reduction of the strain in the casing sensed by the distributed strain sensor.
 8. The system of claim 1, wherein a change in a geometry of the fracture is correlated to a change in fluid flow between the wellbore and an earth formation penetrated by the wellbore.
 9. A method of monitoring at least one fracture in a subterranean well, the method comprising: sensing strain in a portion of a casing where the fracture intersects the casing, the sensing being performed with a distributed strain sensor; and determining a geometry of the fracture, based on the sensing.
 10. The method of claim 9, wherein the geometry comprises a selected one or more of the group consisting of a width of the fracture, a height of the fracture and an orientation of the fracture relative to a wellbore.
 11. The method of claim 9, further comprising performing the strain sensing and geometry determining over time, thereby detecting changes in the geometry of the fracture over time.
 12. The method of claim 9, wherein the distributed strain sensor is positioned external to the casing.
 13. The method of claim 9, wherein the distributed strain sensor extends across the fracture.
 14. The method of claim 9, wherein the distributed strain sensor comprises an optical waveguide.
 15. The method of claim 9, wherein an optical interrogator detects optical scatter in the optical waveguide.
 16. The method of claim 9, further comprising correlating a change in the geometry of the fracture to a change in fluid flow between a wellbore and an earth formation penetrated by the wellbore.
 17. A system for use with a subterranean well, the system comprising: a distributed strain sensor that senses strain along a casing which lines a wellbore, the distributed strain sensor comprising an optical waveguide, wherein the distributed strain sensor extends across at least one fracture that intersects the wellbore.
 18. The system of claim 17, further comprising an optical interrogator that detects optical scatter in the optical waveguide.
 19. The system of claim 17, wherein the fracture extends outwardly from the casing into an earth formation penetrated by the wellbore.
 20. The system of claim 17, wherein closure of the fracture is indicated by a reduction of the strain in the casing sensed by the distributed strain sensor. 